|Publication number||US7513308 B2|
|Application number||US 11/219,223|
|Publication date||Apr 7, 2009|
|Filing date||Sep 2, 2005|
|Priority date||Sep 2, 2004|
|Also published as||US7318480, US20060042791, US20060042799|
|Publication number||11219223, 219223, US 7513308 B2, US 7513308B2, US-B2-7513308, US7513308 B2, US7513308B2|
|Inventors||Stanley Hosie, David S. Christie, Alistair MacDonald, Paul Findlay Milne|
|Original Assignee||Vetco Gray Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (35), Referenced by (29), Classifications (20), Legal Events (4)|
|External Links: USPTO, USPTO Assignment, Espacenet|
Applicant claims priority to the application described herein through a U.S. provisional patent application titled “Tubing Running Equipment For Offshore Rig With Surface Blowout Preventer,” having U.S. Patent Application Ser. No. 60/606,588, which was filed on Sep. 2, 2004, and which is incorporated herein by reference in its entirety.
1. Field of the Invention
This invention relates in general to offshore drilling, and in particular to equipment and methods for running tubing or casing with an offshore rig that uses a surface blowout preventer.
2. Background of the Invention
When completing a subsea well for subsea production, a riser extends from a surface vessel and attaches to the subsea well. A tubing hanger is lowered with a conduit through the riser and landed in the tubing spool and wellhead assembly. A tubing hanger running tool that is connected to the upper end of the tubing hanger sets the seal and locking member of landing of the tubing hanger. A control line extends from the running tool alongside the conduit to the surface platform. A lower marine riser package (“LMRP”) and subsea blowout preventer (“BOP”) can be utilized for safety and pressure control. In arrangements in which the BOP provides the main basis for pressure control, the BOP typically closes in on and engages the outer surface of the tubing hanger running tool.
During certain completion operations, the operator closes the BOP on the outer surface of the tubing hanger running tool. This enables the operator to apply pressure to the tubing hanger for testing purposes. Circulation operations can be performed through the subsea well with the fluid line or the conduit in the riser as either return or entry ways for the fluid. One of the drawbacks of these arrangements is that the LMRP/BOP is very large and bulky with numerous electrical and hydraulic control lines extending from the surface vessel in order to monitor and operate the subsea LMRP/BOP. The drilling riser typically has a large diameter and has a large number of lines extending alongside.
Accordingly, it has been proposed to utilize a surface (BOP) with a smaller subsea disconnect package during completion work on the subsea well. The surface BOP provides well control during the drilling and completion operations. The subsea disconnect package comprises a smaller, less complex assembly, which allows for emergency release of the rig from the well. The riser may be less complex, such as one using threaded joints.
An umbilical is attached to the tubing hanger running tool for supplying hydraulic fluid to the tool to perform various tasks. With a conventional subsea LMRP, the BOP closes on the running tool at a point below the attachment of the umbilical to the running tool. Normally, a BOP cannot seal around a conduit if the umbilical is alongside without damaging the umbilical. This prevents a surface BOP from being used for completion operations in the same manner as a subsea LMRP.
An apparatus for performing operations on an offshore well includes a subsea wellhead assembly. A riser extends from the subsea wellhead assembly to a surface vessel. A tool connects to a running string and is lowered through the riser into the wellhead assembly for performing operations at the wellhead assembly. A subsea controller is located adjacent the subsea wellhead assembly. The subsea controller controls the operation of the tool. A surface controller is positioned on the surface vessel, and is in communication with the subsea controller via a control line extending downward from the surface controller to the subsea controller. The control line extends downward from the surface controller along an exterior of the riser.
The tool can be hydraulically actuated. The apparatus can include a connector extending through a sidewall of the wellhead assembly. The connector is controlled by the subsea controller. The connector is in communication with the tool when the tool is in a desired position. The connector can stroke between a disengaged position and an engaged position.
The subsea controller can be a remote operated vehicle. The remote operated vehicle engages the connector in order to stroke the connector between engaged and disengaged positions. The subsea controller can also be a control pod mounted to an exterior of the subsea wellhead assembly. A control pod line extends from the control pod to the connector.
The subsea controller can also be an acoustical transmitter for transmitting acoustical signals to control the tool. There can also be a relay unit mounted to the wellhead assembly for receiving and transmitting the signals to the tool. A tool signal receiver can also be positioned on the tool. The tool signal receiver actuating the tool upon receiving a signal from the relay unit.
The apparatus can also include an extendable pin that extends through a sidewall of the wellhead assembly into the interior of the wellhead assembly. The extendable pin can be controlled by either the remote operated vehicle or the control pod.
A riser 21 extends from shear rams 19 upward. Most drilling risers use flanged ends on the individual riser pipes that bolt together. Riser 21, on the other hand, preferably utilizes casing with threaded ends that are secured together, the casing being typically smaller in diameter than a conventional drilling riser. Riser 21 extends upward past sea level 23 to a blowout prevent (“BOP”) stack 25. BOP stack 25 is an assembly of pressure control equipment that will close on the outer diameter of a size range of tubular members as well as fully close when a tubular member is not located within. BOP stack 25 serves as the primary pressure control unit for the drilling and completion operation.
Riser 21 and BOP stack 25 are supported by a tensioner (not shown) of a floating vessel or platform 27. Platform 27 may be of a variety of types and will have a derrick and drawworks for drilling and completion operations.
An umbilical line 39 extends alongside conduit 37 for supplying hydraulic and electrical power to running tool 33. Umbilical line 39 comprises a plurality of separate lines within a jacket for controlling the various functions of running tool 33. The functions include supplying hydraulic fluid pressure to running tool 33 for engaging and disengaging with tubing hanger 31, to a lockdown mechanism for tubing hanger 31, and to a piston member for setting a seal. Umbilical line 39 may also include electrically conductive wires. The electrical functions, if employed, may include sensing various positions of the running tool 33 and measuring fluid pressures during testing. The various lines that make up umbilical line 39 extend through disconnect member 35.
At least one upper slick joint 41 is secured to the upper end of conduit 37.
As shown in
Upper slick joint 41 has an outer conduit 45 that is of larger diameter than inner conduit 43, resulting in an annulus between inner conduit 43 and outer conduit 45. Outer conduit 45 has a smooth cylindrical exterior for sealing engagement by BOP stack 25 (
In the operation of the embodiment of
The operator runs control lines 50 from controller 51 to the uppermost penetrator connectors 47 (
For emergency purposes, surface BOP 25 can be closed around upper slick joints 41. Similarly, sealing ram 17 can be closed around disconnect member 35. After the testing of the well has been completed, the operator supplies hydraulic power through umbilical 39 to running tool 33 to release it from tubing hanger 31 for retrieval.
Typically, a number of wells would be drilled in the same general area with the same drilling riser 21 (
Running tool 53 has a receptacle 59 located on its sidewall that leads to various hydraulic and optionally electrical components of running tool 53. Receptacle 59 aligns with a reciprocal connector 61 when tubing hanger 31 is in the landing position and orientation pin 57 has properly oriented running tool 53. Reciprocal connector 61 is mounted to adapter 62 and has a plunger that extends out and sealingly engages receptacle 59.
A control line 63 extends from reciprocal connector 61 to a control pod 65. Control pod 65 is located subsea, preferably on a portion of the subsea pressure control equipment such as shear rams 19. Control pod 65 has electrical and hydraulic controls that preferably include a hydraulic accumulator that supplies pressurized hydraulic fluid upon receipt of a signal. Control pod 65 connects to an umbilical 69 that is located on the exterior of riser 21, rather than in the interior as in the first embodiment. Umbilical 69 extends up to a controller 71 mounted on platform 27.
In the operation of the embodiment of
The operator may also sense various functions, such as pressures or positions of components, through lines 63 and 69. Typically, the operator will test the seal of tubing hanger 31 to determine whether the seal has properly set. This may be done by applying pressure to the fluid in the annulus in riser 21 with BOP 25 closed around conduit 37. Alternately, testing may be done by utilizing a remote operated vehicle (“ROV” not shown in
In the embodiment of
In the operation of this embodiment, ROV 75 first connects to orientation pin 85 and extends it, then is moved to reciprocal connector 73. After running tool 53 has landed tubing hanger 31, ROV 75 strokes reciprocal connector 73 into engagement with running tool 53 and sets tubing hanger 31. Then ROV 75 moves over to test port 68 for providing hydraulic fluid pressure for test purposes in the same manner as described in connection with
In the embodiment of
In the operation of the embodiment of
In each of the embodiments described above, the power and hydraulic line or control line is not exposed to well pressures during completion operations. These embodiments help to reduce the risks of shearing the umbilical line from the surface vessel to the running tool, or having a leak at the surface BOP because of the umbilical line. The embodiments in
While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes without departing from the scope of the invention.
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|U.S. Classification||166/338, 166/255.2, 166/367, 166/360|
|International Classification||E21B43/013, E21B33/035, E21B33/064, E21B29/12|
|Cooperative Classification||E21B33/064, E21B33/0355, E21B43/101, E21B41/0007, E21B43/013, E21B33/035|
|European Classification||E21B33/035, E21B33/035C, E21B43/013, E21B33/064, E21B43/10A, E21B41/00A|
|Nov 3, 2005||AS||Assignment|
Owner name: VETCO GRAY INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:HOSIE, STANLEY;CHRISTIE DAVID S.;MACDONALD, ALISTAR;AND OTHERS;REEL/FRAME:017181/0549
Effective date: 20050907
|Jul 5, 2006||AS||Assignment|
Owner name: VETCO GRAY INC., TEXAS
Free format text: CORRECTIVE ASSIGNMENT TO CORRECT THE THIRD ASSIGNOR S NAME, PREVIOUSLY RECORDED AT REEL 17181 FRAME0549;ASSIGNORS:HOSIE, STANLEY;CHRISTIE, DAVID S.;MACDONALD, ALISTAIR;AND OTHERS;REEL/FRAME:018081/0757
Effective date: 20050907
|Oct 9, 2012||FPAY||Fee payment|
Year of fee payment: 4
|Oct 7, 2016||FPAY||Fee payment|
Year of fee payment: 8